24-Month Reliability Outlook (2014–2015)

24-Month Reliability Outlook
(2014–2015)
Table of Contents
24-Month Reliability Outlook 2014–2015
1
What is the 24-Month Reliability Outlook?
2
How Are We Doing?
3
Expected Load Conditions
7
Supply Adequacy
8
Transmission System Reliability
9
Transmission System Upgrades
11
Current Operating Conditions, Constraints and Potential Adverse Constraints
14
Northwest Region
16
Northeast Region
17
Edmonton Region
19
Wabamun Lake/KEG and Edmonton/Fort Saskatchewan Area Bulk Transmission
20
Central Region
22
South Region
24
North-South Transmission
26
Alberta Intertie Capability
28
Wind Integration
29
Demand Response
30
Highlights of the 24-Month Reliability Outlook
31
In Summary
32
24-Month Reliability Outlook
24-Month Reliability Outlook 2014–2015
Reliable, competitively priced electricity is essential to ensure Alberta’s
long-term growth and our continued high standard of living and prosperity.
The ability of Alberta’s electric system to meet future load growth depends on
continued access to sufficient generation and a robust transmission system.
As the Independent System Operator (ISO) in Alberta, the Alberta Electric System Operator
(AESO) leads the safe, reliable and economic planning and operation of Alberta’s Interconnected
Electric System (AIES). We also facilitate Alberta’s fair, efficient and openly competitive
wholesale electricity market which in 2013 had 176 participants and approximately $8 billion
in energy transactions.
Disclaimer
The information contained in this document is for information purposes only. As such, the AESO makes
no warranties or representations as to the accuracy, completeness or fitness for any particular purpose
with respect to the information contained herein, whether express or implied. While the AESO has made
every attempt to ensure information is obtained from reliable sources, the AESO is not responsible for
any errors or omissions. Consequently, any reliance placed on the information contained herein is at
the user’s sole risk.
24-Month Reliability Outlook
PAGE 1
What is the 24-Month Reliability Outlook?
The AESO’s 24-Month Reliability Outlook (Reliability Outlook) provides a snapshot of the
reliability of Alberta’s electricity grid from the perspective of assessing our ability to meet
electricity requirements until the end of 2015. This sixth annual edition of the Reliability
Outlook includes information on:
n
Expected load conditions, supply adequacy and transmission reliability
of the AIES
n
Transmission system upgrades being put in place to meet performance
requirements, forecast demand and integration of new generation
n
Current operating conditions, constraints and potentially adverse conditions
that could be avoided through coordinated maintenance plans for generation
and transmission facilities
n
Key market initiatives underway
Electric system reliability includes two components: supply adequacy and transmission
system reliability. Supply adequacy means ensuring there is enough electric supply
(generation) to meet consumers’ demand for power. Transmission system reliability is the
ability to withstand sudden disturbances or the unanticipated loss of facilities in the system.
One of the AESO’s roles is to ensure the electric system is robust and ready to keep the
lights on for Albertans.
PAGE 2
24-Month Reliability Outlook
How Are We Doing?
Over the next two years, Alberta’s economy is expected to grow. According to the
Conference Board of Canada, Alberta’s economic growth, as measured by gross domestic
product (GDP), will increase by 3.6 per cent in 2014 and three per cent in 2015. Alberta is
expected to experience strong economic growth over the next five years and the long term,
as investment in the oilsands spurs economic growth and jobs.
While new generation has kept pace with demand, growth over the last 10 years has loaded
the existing transmission system to its capacity. From 2011 to 2013, annual energy
consumption growth was 2.5 per cent, with strong growth in the oilsands sector and
continued growth in other industries.
Parts of the electric system continue to experience constraints that limit the ability to
transmit power between various locations in Alberta. In some parts of the province,
constrained transmission lines can strand electricity supply, making it unavailable to the
market. In other areas, constraints occur when there is not enough transmission capacity
to serve local load. For example:
n
Transmission must-run (TMR) services are required in the Northwest Alberta
and Calgary areas to maintain system reliability
n
Wind power generation constraints continue in the Southwest Region and are
expected to continue until Southern Alberta Transmission Reinforcement (SATR)
is fully energized
n
Some regions (see Table 1, Page 5) experience generation or load constraints
when transmission facilities are taken out of service for planned maintenance
or by forced outages
24-Month Reliability Outlook
PAGE 3
Constraints arising from the addition of new load and generation connections, forced
outages, and planned outages (e.g., for maintenance and integrating new facilities) are
continuing to impact reliability as demonstrated in Tables 1 to 4. The AESO is meeting
this challenge through:
n
Planning transmission system development
n
Ongoing emphasis on coordination of planned outages
n
Developing and implementing reliability standards and operating tools
and procedures
n
Augmenting training and introducing new programs to help system operators
manage and maintain system reliability
n
Developing operating limits and tools in advance of each project stage
of transmission development
With the addition of new generation and continued demand growth, we expect the level of
congestion on the AIES to continue until transmission reinforcement is completed. For the
AESO, timely approval and installation of proposed transmission upgrades remain a priority.
At the end of 2013, total installed generation capacity on the Alberta system was over
14,568 megawatts (MW) and the record winter season peak demand of 11,139 MW was
reached on December 2, 2013.
Table 1 summarizes constraint events considered to form part of abnormal operating
conditions. Constraints can result from outages for planned maintenance, outages planned
for adding new facilities to the grid, or forced outages of transmission elements. Table 2
identifies the number of hours where abnormal operating conditions on different cutplanes
resulted in limited transfer capability. There were many periods where the limited transfer
capability did not result in constraints.
Generation curtailment data is aggregated from the System Controller shift log entries
that include start times, end times, affected assets and cause of real-time congestion.
Overlapping curtailment directives are counted together when generating assets are located
in the same area and are due to the same cause. Overlaps for assets in separate areas are
not combined and are counted as separate events. Events are counted as separate if they
carry on to the following month.
PAGE 4
24-Month Reliability Outlook
Table 1: Summary of Transmission Constraint 1 Events on AIES Cutplanes 2009–2013
Cutplane or area
2009
2010
2011
2012
2013
12
42
16
14
13
Keephills-Ellerslie-Genesee (KEG)
2
19
2
18
7
South of KEG (SOK)
1
8
0
0
3
68
96
72
79
25
South of Anderson
1
1
11
7
13
Edmonton Area
0
0
1
7
2
23
13
13
18
17
Fort McMurray
Wind
Other
2
Table 2: Summary of Abnormal Operation Resulting in Transmission Path or Area Limit
Reductions3 2009–2013 (hours per year)
Cutplane or area
2009
2010
2011
2012
2013
Fort McMurray
769
990
670
1386
8704
Keephills-Ellerslie-Genesee (KEG)
180
1,121
461
117
122
South of KEG (SOK)
591
1,410
4,871
2420
2,7625
Wind
866
1,490
1,224
1,186
2,557
South of Anderson
0
1,096
58
630
748
Edmonton Area
0
0
15
37
13
166
275
157
249
582
Other
Constrained-down generation (CDG) occurs primarily when the amount of power a generator
can supply to the system is limited by insufficient transmission capacity. During a CDG
event, the AESO System Controller enacts mitigation steps in the sequence specified by ISO
Rule Section 302.1: Real Time Transmission Congestion Management (TCM). Tables 3 to 4
on Page 6 provide historical information on CDG volumes, and the duration and frequency
of CDG events. The data are categorized into TCM Areas consistent with the definitions
given by the Information Documents associated with ISO Rule Section 302.1.
Previous reporting of CDG in the 24-Month Reliability Outlook has been based on the
transmission line limits enforced during transmission constraint events, rather than on
actual in-merit energy that is constrained down during an event. Simply put, when an
AESO System Controller (SC) identifies a transmission constraint in an area, a transmission
limit is put in place for reliability purposes to prevent generation dispatches above a
determined energy level for an area. In previous CDG reporting, the AESO used this level
Most of the southwest wind constraints occurred during system normal operation; most other constraints occurred
under abnormal operation.
1
These are constraints in AIES areas where operation is not managed by a cutplane.
2
Mostly due to planned or forced maintenance activity.
3
444 hours had 50-130 MW and 426 hours had 160-230 MW reduction in transfer out limit during 2013 for the
Fort McMurray area.
4
1,835 hours had 150-300 MW and 927 hours had 400-550 MW reductions in SOK path transfer limit during 2013.
5
24-Month Reliability Outlook
PAGE 5
as a proxy for constrained-down generation. However, it is possible that actual in-merit
generation varies during the constraint event and, although a constraint may exist for a
period of time, the constrained generation volume may be below the initial reported limit.
When in-merit generation is below a system limit, no generation is constrained down. In
this case, using the system limit to proxy constrained power overestimates CDG volumes.
To provide the most accurate representation of CDG volumes, the AESO undertook further
analysis of the information available to estimate in-merit CDG 6 (Estimated CDG). The results
presented below use volumes of Estimated CDG, and therefore differ from the information
presented in previous 24-Month Reliability reports. The AESO believes this new
methodology provides a more realistic representation of CDG; however, it remains an
estimate, and has limitations due to the process and systems used for data capture.
Table 3 provides the estimated GWh amount of generation constrained annually from
2011 to 2013. The AESO notes that the Keephills-Ellerslie-Genesee (KEG) and Northeast
areas account for most of the estimated CDG in the period. Table 4 provides the total
duration of constraints on an annual basis.
Table 3: Annual Total Constrained-Down Generation (GWh)
GWh
Year
Central
East
2012-018
Cold Lake
2012-015R
Crossfield
2012-017R
KEG
2014-004R
NorthSouth
2013-002R
Northeast
2011-008R
Northwest
2011-004R
South
2013-009R
All
2011
4
0
1
81
5
14
0
3
108
2012
7
0
0
54
0
21
0
1
84
2013
19
0
2
43
1
33
3
2
103
Table 4: Number of Hours with Constrained-Down Generation7
Total Hours
Year
Central
East
2012-018
Cold Lake
2012-015R
Crossfield
2012-017R
KEG
2014-004R
NorthSouth
2013-002R
Northeast
2011-008R
Northwest
2011-004R
South
2013-009R
All
2011
84
0
29
304
44
384
0
861
1,465
2012
71
0
10
196
5
335
12
294
932
2013
246
7
193
126
10
503
311
388
1,596
This method looks at the merit order snapshot and estimates the amount of in-merit CDG of assets in the area where
the CDG took place. Given this methodology for estimating in-merit CDG, constrained-down wind generation is not
included in the Estimated CDG.
6
Number of hours with CDG and number of events will not sum to All as there may be events across multiple
Transmission Constraint Management Areas in a particular hour.
7
PAGE 6
24-Month Reliability Outlook
Expected Load Conditions
Alberta is expected to show steady economic growth over the long term. According to
the AESO 2014 Long-term Outlook (LTO), average annual demand is forecast to grow
by 4.4 per cent for the next five years.
For the 2013–2014 winter season, the Alberta Internal Load (AIL) 8 winter peak demand
reached a high of 11,139 MW, surpassing the all-time peak of 10,609 MW; the 2013 summer
peak reached a record high of 10,063 MW. Long-term load forecast winter peaks are
11,323 MW for 2014–2015 and 11,811 MW for 2015–2016. On a year-over-year basis,
Alberta’s total energy consumption for 2013 was 2.5 per cent higher than 2012.
Figure 1 shows AIL yearly actual and forecast peak loads from 2005 to 2015. Actual load
for the period November 2013 to November 2015 will depend on factors such as:
n
Weather conditions
n
Actions of price-responsive load (approximately 300-350 MW)
n
New oilsands projects and associated industry coming on stream
Figure 1: Annual Actual and Forecast Summer and Winter Peak Loads
12,500
12,000
11,500
Peak AIL (MW)
11,000
10,500
10,000
9,500
9,000
8,500
8,000
2005
Summer Peak
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
Winter Peak
Alberta Internal Load (AIL) is defined as the province’s total electricity consumption, including losses through
transmission and distribution, as well as load served by behind-the-fence generation.
8
24-Month Reliability Outlook
PAGE 7
Supply Adequacy
This section discusses whether there will be enough generation to supply total electrical
demand and meet operating reserve requirements over the next two years. In Alberta,
investor-driven market decisions will determine the amount of generation added to the
electricity system in the next two years. Information on past development, the status of
current development, major supply increases or decreases and a summary of supply
adequacy results are discussed.
Over the past few years, the province has seen continued investment in generation projects,
with approximately 720 MW of net additions in 2012 and 164 MW of net additions in 2013.
In 2013, cogeneration and waste heat generation added the most capacity to the system.
These additions include cogeneration additions at MEG Energy Corp, the addition of
NRGreen Power Ltd., installation of a new waste heat generation near Whitecourt, and
a number of capacity increases at existing generation sites.
There are 1,171 MW of generation projects under construction that are expected to connect
to the grid by November 2015. Additional generation projects that intend to start operations
in the next two years include approximately 1,307 MW that have received Alberta Utilities
Commission (AUC) power plant approval and an additional 1,675 MW that have been
announced corporately or have applied for regulatory approval. Cogeneration facilities
make up a large portion of the projects expected to come online in the next two years. This
investment is considered to be adequate to meet the growth in demand and compensate
for generation retirements.
It is expected that existing and new generation is adequate to meet daily peak demand
over the next two years, as indicated by the daily supply cushion in the AESO’s supply
adequacy assessments. To ensure transmission congestion does not strand a significant
amount of generation, it will be necessary to continue to closely coordinate generator and
transmission outages.
The AESO performs a number of assessments to monitor the ability of supply to serve firm
demand and satisfy contingency requirements in the short-to-medium term (one day to
24 months) and the long term (up to five years). These assessments indicate supply reserve
margins will be adequate during the next two years, but close coordination of generator and
transmission outages is required to ensure adequate supply and to avoid constraint events
during the real-time operation. Further information on constraint events can be found at
www.aeso.ca
PAGE 8
24-Month Reliability Outlook
Transmission System Reliability
Transmission system reliability—sometimes referred to as operating reliability or system
security—is described as the ability of the electric system to withstand sudden disturbances
or the unanticipated failure of system elements.
In a May 2008 North American Electric Reliability Corporation (NERC) paper, submitted as
an information filing to the Federal Energy Regulatory Commission (FERC), the following
definition was offered to describe an adequate level of reliability, drawing a distinction
between customer service reliability and transmission system reliability:
The System:
n
Is controlled to stay within acceptable limits during normal conditions
n
Performs acceptably after credible contingencies
n
Limits the impact and scope of instability and cascading outages when
they occur
n
Facilities are protected from unacceptable damage by operating them
within facility ratings
n
Integrity can be restored promptly if it is lost
n
Has the ability to supply the aggregate electric power and energy requirements
of the electricity consumers at all times, taking into account scheduled and
reasonably expected unscheduled outages of system components
As it relates to reliability, risk is the likelihood that an event (i.e., an outage or change in
operating conditions) will reduce the reliability of the power system to the point that the
consequences are unacceptable (e.g., equipment damage or cascading outages). Since
sudden disturbances or the unanticipated failure of system elements are unforeseen and
not preventable, the AESO needs to plan and operate the electric system so that when these
events occur, the effects are manageable and consequences are acceptable as defined
in the Alberta Reliability Standards and AESO Reliability Criteria. It is critical to effectively
manage risk to ensure the power system is operated within the performance requirements.
24-Month Reliability Outlook
PAGE 9
To do this, the AESO assesses system reliability and operability for customer connections
and regularly performs operations planning studies to assess the operability and reliability
of the transmission system under a broad range of operating conditions. The AESO uses
an operating horizon methodology to establish system operating limits (SOLs) and these
are implemented through operating procedures that protect generation and transmission
equipment from damage that could jeopardize reliability for weeks or even months. The
study results are also used to support integration of new generation and transmission
facilities and to facilitate the coordination of outages.
Reliable system operation depends on a continuously connected and managed power
system with synchronized generation, transmission and load. System operators monitor
the overall reliability of the power system on a moment-by-moment basis by keeping flows
and voltages within established limits while balancing supply with demand.
Another safeguard of Alberta’s electric system reliability is the AESO’s adherence to
standards and criteria developed by NERC and the Western Electricity Coordinating Council
(WECC). The NERC reliability standards and WECC criteria and business practices are
central to assessing the adequacy of the existing and future transmission system. With
an adequately planned system and prudent operating criteria, we can operate the system
reliably while facilitating an open and competitive market. The AESO carries out studies
using the standards and reliability criteria on a regular basis.
PAGE 10
24-Month Reliability Outlook
Transmission System Upgrades
One of the AESO’s priorities remains timely approval and implementation of proposed
transmission upgrades in order to meet future electricity demand, connect generation,
satisfy reliability requirements and upgrade the power system in the public interest
of Albertans.
These proposed upgrades include improving the transfer capacity of interties that
connect Alberta’s transmission system to the neighbouring jurisdictions of Saskatchewan,
British Columbia and Montana. Alberta’s electric system reliability is enhanced by these
interconnections, which allow us to import power to meet peak demand in the summer
and winter and help alleviate power shortages by providing access to additional back-up
power in case of sudden equipment failure.
To keep pace with Alberta’s continued growth in load and generation and enhance reliability,
several transmission upgrades across the Alberta transmission system were completed
in 2013.
NW Region Projects commissioned in 2013:
n
A new -30/+50 MVAr synchronous condenser energized at Arcenciel 930s
n
A new 144 kV line 7L162 between Otauwau 729S and Mitsue 732S
n
A new 144 kV line 7L172 between Edith Lake 739S and Sarah Lake 743S
24-Month Reliability Outlook
PAGE 11
NE Region Projects commissioned in 2013:
n
A new 240 kV substation Livock 939S and terminated 240 kV 9L57 and 9L10 lines
n
A new 600 MVAr 240kV phase-shifting transformer at Livock 939S
n
New 240kV substations; McClelland 957S and Bitumont 941S
n
A new 240kV line 9L32 from Joslyn 849S to Bitumont 941S to McClelland 957S
n
A new 240kV line 9L69 between McClelland 957S and Black Fly 934S
n
New 240 kV substations; Black Spruce 154S and Jack Fish 698S in the
Christina Lake area
n
Three new 138 kV capacitor banks; 10MVAr, 14MVAr and 18MVAr at Winefred 818S
n
A new 144 kV 7L587 line between Marguerite 826S and Wolf Lake 822S;
the existing line 7L87 will be salvaged to remove thermal constraint of the 7L87
n
A new 144 kV 7L574 line between Wolf Lake 822S and Bourque 970S;
the existing line 7L74 will be salvaged to remove thermal constraint of the 7L74
n
A new 144 kV substation; Bourque 970S in the Cold Lake area
n
Two new 144 kV double circuit 7L160/7L157 lines between Bourque 970S
and Mahihkan 837S
n
One terminal of 7L83 moved from Mahihkan 837S to Bourque 970S
Edmonton Region and Fort Saskatchewan Area Projects commissioned in 2013:
n
A new 500/240 kV transformation substation at Heartland 12S
n
Two new 500kV lines 1206L/1212L between Ellerslie 89S and Heartland 12S tied
and energized at 240kV pending the energization of the 500/240 kV transformer
n
The 240kV 942L line (71S–13S) was terminated as in-and-out at Heartland 12S
and lines numbered as 932L (Lamoureux 71S–Heartland 12S) and 1054L
(Heartland 12S–Deerland 13S)
n
Restringing eight km of 902L between Wabamun 19S and Sundance 210P to
higher-rated conductor
PAGE 12
24-Month Reliability Outlook
Central Projects commissioned in 2013:
n
A new 240/138kV T3 transformer; Benalto 17S
n
Three new 138 kV capacitor banks; 50 MVAr at Joffre 535S, 50 MVAr at
Prentiss 276S and 27.6 MVAr at Ellis 332S
n
A new 240kV substation at Oakland 946S
n
Two new 240kV double-circuit lines 9L70/9L97 between Oakland 946S
and Anderson 801S
n
A new 144 kV substation at Heatburg 948S with 7L16 terminated as in-and-out
n
A new 144 kV line 7L143 between Stettler 769S and Nevis 766S
n
A new 240/144 kV transformation substation at Coyote Lake 963S
n
A new 240 kV line 9L29 between Coyote Lake 963S and Oakland 946S
n
A new 144 kV line 7L128 between Michichi Creek 802S and Coyote Lake 963S
n
Two new 240/144 kV transformation substations at Lanfine 959S and Pemukan 932S
n
A new 240 kV line 9L24 between Lanfine 959S and 946S Oakland
n
A new 240 kV line 9L46 between Lanfine 959S and Pemukan 932S
n
A new 240kV line 9L966 between Hansman Lake 650S and Pemukan 932S
n
A new 144 kV line 7L132 between Oyen 767S and Lanfine 959S
n
A new 144 kV line 7L127 between Pemukan 932S and Monitor 774S
n
A new 144 kV line 7L116 between Lanfine 959S and Excel 910S
n
A new 138 kV substation at Tucuman 478S
n
A new 240/138 kV transformation substation at Nilrem 574S
n
The 9L953/953L 240kV line terminated into Nilrem 574S as in-and-out
n
Two new 138 kV lines 679L/680L between Nilrem 574S and Tucuman 478S
n
A new 240 kV line 1053L between Ware Junction 132S and Cassils 324S
n
A new 144 kV line 7LA701 between Heisler 764S and 7LA701 tap off
South Region Projects commissioned in 2013:
n
A 138kV new ENMAX SS-54 substation
n
A new 240/138 kV transformation substation at ENMAX SS-65
n
A new 240 kV substation ENMAX SS-25 for Shepard Connection
n
Montana–Alberta Intertie (MATL)
n
A existing 911L line was converted into three lines as 911L (Peigan 59S–ENMAX
SS-65), 1080L (ENMAX SS-65–ENMAX SS-25) and 1003L (ENMAX SS-25–
Janet 74S) 240kV line 933L between Ware Junction 132S and Anderson 801S
n
Existing 240 kV 933L (Anderson 801S–W. Brooks 28S) was terminated at
Ware Junction 132S with 933L (Anderson 801S–Ware Junction 132S) and 1075L
(Ware Junction 132S–W. Brooks 28S)
n
A new 138kV line 832L between ENMAX 10 and ENMAX 12
n
A new 138kV line 693L between Sarcee 42S and ENMAX 10
24-Month Reliability Outlook
PAGE 13
Current Operating Conditions, Constraints
and Potential Adverse Constraints
The following sections describe the operating conditions, system operating limits and
potential adverse constraints that might occur in each region of the transmission system
during the 2014 summer operating season and to the end of the 2015 time frame of this
Reliability Outlook.
The operation of the power system in Alberta has two seasons, winter and summer.
The winter season is effective from Nov. 1 of the year to April 30 of the following year. The
summer season is May 1 to Oct. 31 of the year. Peak demand and thermal facility ratings9
of transmission equipment are typically higher in the winter and lower in the summer.
Any planned maintenance on transmission and generating assets that would occur in
the summer season will often result in more stress on the transmission system, increasing
the potential for operating constraints.
When the overall Alberta supply reserve margin is low, most generators are expected to be
in service10. High market prices for energy are likely to attract imports, which bring power
into the south central part of the transmission system. Higher winter thermal ratings of
transmission facilities, and most supply being in merit during peak periods should create
a generally sufficient level of transmission reliability for the summers of 2014 and 2015,
and winter 2014/2015.
As system load continues to grow and generation develops in specific areas, the effects of
contingencies (sudden failures or outages on the system) become increasingly pronounced.
To manage these risks, close coordination of generator and transmission outages is
required to ensure adequate supply and avoid constraint events during real-time operation.
The AESO is meeting this challenge through transmission development and continued
emphasis on coordination of planned outages and developing enhanced operating tools,
real-time studies, procedures and training for our system controllers, and an ongoing
emphasis on comprehensive analysis and follow-up should disturbances occur.
There continue to be operating challenges in all the regions of the province that require
constraint management and special operating procedures, use of transmission must-run
(TMR) generation, remedial action schemes (RAS) and coordination of transmission and
generation outages. These are described in the following sections.
Thermal ratings are the maximum amount of electrical current transmission facilities can conduct over a
period of time without overheating and causing permanent damage or violating equipment safety margins.
9
This means a designation applied to an asset dispatched by the system controller that qualifies the asset
as eligible to set the marginal price.
10
PAGE 14
24-Month Reliability Outlook
Figure 2: Alberta Transmission System Planning Regions
17
Rainbow Lake
18
High Level
25
Fort McMurray
19
Peace River
20
Grande Prairie
22
Grande Cache
23
Valleyview
24
Fox Creek
21
High Prairie
27
Athabasca/Lac La Biche
26
Swan Hills
40
Wabamun
29
Hinton/Edson
38
Caroline
Calgary
Northeast
Central
Northwest
Edmonton
South
37
Provost
42
Hanna
39
Didsbury
57
Airdrie
45
6
Calgary Strathmore/
Blackie
46
High River
Region Names
13
Lloydminster
32
Wainwright
36
Alliance/Battle River
35
Red Deer
44
Seebe
56
Vegreville
31
Wetaskiwin
30
Drayton Valley
34
Abraham Lake
33
Fort
60 Sask.
Edmonton
28
Cold Lake
43
Sheerness
47
Brooks
49
Stavely
53
Fort MacLeod
54
Lethbridge
52
Vauxhall
48
Empress
4
Medicine Hat
55
Glenwood
24-Month Reliability Outlook
PAGE 15
Northwest Region
The Northwest Region of Alberta is a geographically large area northwest of the City
of Edmonton. It is bordered by Fort McMurray and Athabasca to the east, Hinton and
Wabamun to the south, B.C. to the west, and the Northwest Territories to the north. While
this region represents approximately one-third of the area of the province, it represents
only one-tenth of total demand on the electric system.
The Northwest Region includes the Rainbow Lake, High Level, Peace River, Grande Prairie,
High Prairie, Grande Cache, Valleyview, Fox Creek and Swan Hills planning areas, but
not the Wabamun Lake area. It is connected to the Wabamun Lake area primarily through
three 240 kV transmission lines and is connected to the Fort McMurray area through one
240 kV transmission line. The Northwest Region contains approximately 10 per cent of
the provincial peak load and is a net load area. Due to this imbalance, the region relies
on transfer of power from the Wabamun Lake and Fort McMurray areas.
The reliability of the Grande Prairie area is managed by keeping the flow of the Grande
Prairie cutplane within its system operating limits which sometimes requires transmission
must-run (TMR) services to meet performance requirements as the area does not have
sufficient local transmission capacity. The amount of TMR services required depends
on whether or not the power transfer to this area exceeds specific limits11 which are
specified in Appendix 4 or AESO Rule document Northwest Area Transmission Constraint
Management, ID # 2011-004(R).
The Rainbow Lake area transmission development approved as part of Northwest Area
Transmission Development was completed in 2013, which includes upgrades of 7L64
and energization of a new synchronous condenser at the Arcenciel 930S substation.
After these two facilities are upgraded, the Rainbow Lake area transmission system will
have the capacity to support area load without any TMR under system normal conditions.
Under system-abnormal operation during planned or forced transmission equipment
outages, TMR may be required depending on the flow and system operating limit of
the Rainbow Lake cutplane12.
Transmission facilities commissioned or expected to be commissioned in the Northwest
Region during 2014 and 2015 include:
n
High Prairie 787S 144/72 kV transformation and 7L48/7L06 144 kV lines in/out
These additions will improve area transfer capability and voltage control and reduce the
dependence of area load on TMR services.
11
Limits are based on transmission system conditions and the amount of base-loaded generation online in real time.
12
ID # 2011-004(R) lists system operating limits of the Rainbow Lake cutplane “RLC”.
PAGE 16
24-Month Reliability Outlook
Northeast Region
The Northeast Region of Alberta is bounded on the north by the Northwest Territories, on
the east by the Saskatchewan border, on the west by the fifth meridian, and on the south
by the Edmonton, Wetaskiwin, Vegreville and Lloydminster planning areas. The Northeast
region includes the Fort McMurray, Athabasca/Lac La Biche, Cold Lake and Fort
Saskatchewan planning areas.
The Northeast Region is forecast to experience the greatest load growth of any planning
region in Alberta over the next 10 years. This is due in large part to growth in the oilsands,
including mining, upgrading, and related secondary service industries within the region.
Load in the Northeast Region is predominantly industrial and makes up approximately
25 per cent of provincial peak load. The majority of the electrical load and generation in
the region is located in oilsands developments north of Fort McMurray, and in the Cold
Lake and the Fort Saskatchewan areas. Generation in the region is mainly gas-fired
cogeneration, accounting for 3,400 MW of Alberta’s total installed generation capacity.
The Fort McMurray area is connected to the transmission system by three 240 kV
transmission lines. The area operation in real time is managed by the system operating limits
of the outflow and inflow cutplanes as per AESO document Northeast Area Transmission
Constraint Management, ID# 2011-008(R).
Historically, this area has outflow to the AIES most of the time. The area continues to
experience high load growth related to oilsands development and new transmission
developments being energized every few months to serve the local area connection projects
and to ensure that the local area meets performance requirements.
The current transmission system does not have the capacity to supply the entire load of the
Fort McMurray area without support from local generation. However, a significant amount
of the area generation is baseload industrial cogeneration and, under normal operating
conditions, is adequate to support reliable operation. Longer-term plans include the
construction of 500 kV lines into this area.
With the addition of new 240kV lines 9L84 (Salt Lake Creek 977S to Black Fly 934S) and
9L69 (Black Fly 934S to McClelland 957S), a 240kV loop is formed in the Fort McMurray
area. The Fort McMurray area NE 240kV loop increases Fort McMurray area transfer-out
capability, which also improves Long Lake and Christina Lake generation contribution under
system contingency. It’s expected that in 2015, with the 240kV Dawes substation in service
and the Christina Lake 240kV loop formed, Fort McMurray area transfer capability will be
further improved.
24-Month Reliability Outlook
PAGE 17
Planned outages to integrate new connection projects are expected to continue over the
next two years and beyond. The impacts will be mitigated through outage coordination,
following AESO rules and practices.
The Cold Lake area has surplus generation and thermal constraints on the transmission
system during system abnormal operation that are managed through remedial action
schemes (RASs). On February 10, 2011, the Alberta Utilities Commission approved the
Central East Transmission Development (CETD) Needs Identification Document (NID)
for the Central East Region (which includes development in the Cold Lake area) that will
address long-term transmission needs. The NID includes construction of two new lines
and a substation. In addition, a number of existing 144 kV lines will be upgraded to a higher
rating to alleviate existing bottlenecks. This transmission system development will facilitate
both projected load growth and the connection of cogeneration facilities in the Cold Lake
area. Due to the anticipated delays of the transmission reinforcements to 2013 and 2014,
coupled with load growth in the Cold Lake area, new RASs and operating policies and
procedures (OPPs) remain under consideration as an interim solution for mitigating
transmission constraints.
With the expectation of two 90 MW Nabiye units in service at the end of December 2014,
under FMM, high-export condition 138kV lines 7L53 from Bonnyville to Irish Creek and
7L117 from Irish Creek to Vermilion could be overloaded.
The load growth in the Northeast Region during the last few years is causing constraints
on the Northeast planning cutplane (the 240 kV transfer path between Edmonton and
Fort Saskatchewan areas) in real-time operation. The commissioning of the phase-shifting
transformer at Livock during Q3 2013 and completion of the Heartland Transmission Project
during the second half of 2013 will help alleviate these constraints. They will also support
local demand in the Heartland area, accommodate future demand in northeast Alberta
including Fort McMurray, and provide effective system integration for the Eastern Alberta
Transmission Line (EATL) and the Western Alberta Transmission Line (WATL) projects.
The Heartland project has benefits to the local area and some 240kV lines (921L, 908L, and
915L) and it is also able to minimize KEG generation curtailment under some contingencies.
Operations planning studies are finished to incorporate the Livock 939S phase-shift
transformer into system controller procedures. The procedure will provide guidelines
on how to operate two phase-shifting transformers (one existing at Keephills 320P and
a new one at Livock 939P) in a coordinated manner to mitigate system constraints in the
Edmonton Region.
Transmission facilities commissioned or expected to be commissioned in the Northeast
Region during 2014 and 2015 include:
n
A new 500/240 kV transformer at Heartland 12S
n
Number of 240 kV lines, 240/138 kV substations and 144 kV lines in the
Fort McMurray area to connect new oilsands projects
n
A new 144 kV 7L146 line between Bourque 970S and Bonnyville 700S
PAGE 18
24-Month Reliability Outlook
Edmonton Region
The Edmonton Region encompasses the City of Edmonton and includes the Wetaskiwin,
Wabamun and Edmonton planning areas. This region is the hub of Alberta’s electric
system, comprises over 20 per cent of provincial peak load, and has 4,900 MW of Alberta’s
generation capacity. Most of the generation is baseload, coal-fired power located around
Wabamun Lake, and flows east and south with smaller amounts flowing north and west.
The transmission system in the Edmonton Region has the capacity to serve firm load in the
region when all transmission elements are in service and baseload generation is online in
the Fort Saskatchewan and Wabamun Lake areas. During 2012, within the City of Edmonton,
the condition of aging 72 kV cables surfaced as a concern after preliminary testing. Also,
at the City of Edmonton Garneau substation, overload conditions following a contingency
were identified on the 72 kV cables. The AESO and EPCOR are developing long-term
transmission solutions to mitigate these potential constraints.
The 138 kV system south and west of the City of Edmonton is thermally constrained due to
increased load in the area. During high load conditions, Category B13 events may overload
the 138 kV lines, creating a risk of the system not meeting reliability criteria. When one
transmission element is out of service due to planned or forced outages, there are several
local area constraints on the 138 kV systems. These constraints and contingencies only
affect local areas within the region, and risks are not expected to spread to the 240 kV
backbone of the system.
The AESO filed the NID South and West of Edmonton Transmission Development
http://www.aeso.ca/downloads/R_South_and_West_Edmonton_Area_Transmission_
Reinforcement_Needs_Identification_Document.pdf with the AUC on December 14, 2012
for reinforcement to this 138 kV system. Development is scheduled to be in place by the
end of 2015. In the meantime, the AESO has developed a procedure to mitigate overloads
in the area during real-time operation.
Transmission facilities are commissioned or expected to be commissioned in the Edmonton
Region during 2014 and 2015 and include:
13
n
Re-terminating existing 909L at Sundance 310P
n
Re-routing 1043L 240 kV line between Keephills 320P and Petrolia 816S
Category B events result in the loss of any single specified system element under specified fault conditions and
normal clearing.
24-Month Reliability Outlook
PAGE 19
Wabamun Lake/KEG and Edmonton/
Fort Saskatchewan Area Bulk Transmission
The Wabamun Lake area has undergone major transmission upgrades as part of the
interconnection of the Keephills 3 generator and the related Edmonton Regional 240kV
Lines Upgrades (also referred to as the Edmonton Debottlenecking Project). Construction
of these transmission system upgrades began in the summer of 2010 and is expected to
be completed in 2014.
This area currently is operating under temporary system configuration until the final phase
of the debottlenecking project is complete14. The AESO system controller mitigated the real
time constraints by issuing conscripted TMR to effective area generators and reconfiguring
the system whenever possible to reduce TMR requirements.
After the debottlenecking project is complete, three 240 kV lines will be in place to transport
electricity from the Sundance generating plants to the Edmonton area. Two 500 kV lines
and one new 240 kV line will connect the Keephills and Genesee generating plants to
the Edmonton area. The 240 kV phase-shifting transformer in the path of the 240/500 kV
transformation at the Keephills plant 320P will help mitigate Category B and C15 overloads
and, in combination with the phase-shifting transformer at Livock 939S, will facilitate
increased transfer capacity to serve the Northeast Region.
Operations planning studies were completed in 2011 for the final stage of the Wabamun
Lake area transmission upgrade to determine the system operating limits (SOL) of the
Keephills-Genesee, South of Keephills-Ellerslie-Genesee (SOK) and Northeast16
cutplanes and to ensure the area operates to the Alberta reliability criteria and standards.
The debottlenecking project includes 240 kV line 1043L between Keephills 320P and Petrolia 816S, re-termination
of the 909L between Sundance 310P and Dome 665S, and a 240 kV phase-shift transformer at Livock 939S in the
Fort McMurray area.
14
15
Category C events result in the loss of two specified system elements under specified fault conditions and include
both normal and delayed fault clearing events.
The Northeast cutplane consists of four 240 kV circuits: 920L (Clover Bar 987s to Lamoureux 71s), 921L (Castle
Downs 557s to Lamoureux 71s), 9L56 (Mitsue 732s to Brintnell 876s) and 9L15 (Brintnell 876s to Wesley Creek 834s).
They provide transfer paths for energy to and from the Northeast Region.
16
PAGE 20
24-Month Reliability Outlook
The implementation of the revised procedure is being held until the whole project can be
commissioned–which has been delayed to address stakeholder concerns. After all the
facilities of the project are in place, the operating practices and operator tools will be
revised to implement system operating limits as determined by these studies.
Having WATL and EATL in service will increase transfer capability and system operation
flexibility, reduce constraints, and optimize system losses. For the Keephills-EllerslieGenesee (KEG) area, having WATL in service will significantly improve KEG area transfer
capability and result in no limitation for KEG generators under normal or one-element
outage when Sunnybrook is fully capable of receiving 1,000 MW. Also, WATL and EATL
can be used to mitigate transmission overload in this area under contingency.
The reactive support limitations on legislated Power Purchase Arrangement units in the
KEG area and Sundance plant can create operational concerns. The AESO continues
to work with generator owners and operators to address this issue.
24-Month Reliability Outlook
PAGE 21
Central Region
The Central Region is located between Edmonton and Calgary and includes the
Lloydminster, Hinton/Edson, Drayton Valley, Wainwright, Abraham Lake, Red Deer, Alliance/
Battle River, Provost, Caroline, Didsbury, Hanna and Vegreville areas. This region contains
approximately 15 per cent of the provincial peak load and generation capacity totals over
2,000 MW. Area generation is a mix of hydro, coal-fired, wind, biomass and industrial
gas-fired cogeneration.
The transmission system in the Central Region has the capacity to serve firm loads in
the region when all elements are in service during normal operation. When the system is
operating with one element out of service (N-1), a number of “next contingency” scenarios
can result in voltage violations and/or overloads in different parts of the region. Reliable
transmission system operation is maintained through established procedures, system
operating limits and AESO–TFO coordination of planned maintenance through weekly
system coordination plans.
The Central East Transmission Development (CETD) approved by the AUC in 2011 covers
144 kV systems in the Cold Lake area of the Northeast Region and some areas of the
Central Region. This development will resolve the existing constraints and facilitate the
connection of wind projects, cogeneration and load growth of new pipelines. Due to
anticipated delays of some transmission system reinforcements in the Central Region,
coupled with load growth and the addition of wind generation in this region, new RAS
and procedures are proposed to mitigate constraints in the interim period.
Due to additional wind connection requests that were not included in the CETD NID
development, some facilities of the CETD are under review. This review will introduce
changes to CETD or a separate NID for transmission development for the region to connect
customers and ensure the region meets performance requirements.
Phase one of the Hanna Region Transmission Development project was completed in the
first quarter of 2014. The completion of this project will provide transmission capacity to
mitigate existing transmission constraints, meet load growth of major pipeline projects
and facilitate connection of new wind projects in the Hanna area. It will also improve the
performance of the transmission system with respect to meeting the requirements of
applicable Alberta Reliability Standards and significantly increase current system
operating limits on the South of Anderson (SOA) cutplane.
PAGE 22
24-Month Reliability Outlook
The 2012 approved transmission development for the Red Deer and Didsbury areas has
a revised target completion date of Q3 2015 and this development is planned to mitigate
existing system constraints including thermal overloads on the 138 kV system parallel to
the SOK 240 kV path, meet load growth, and connect new generation in the study areas.
Transmission facilities commissioned or expected to be commissioned in the Central
Region during 2014 and 2015 include:
n
Addition of a -100/+200 VAr SVC at Lanfine 959S
n
St. Paul Area Upgrade 7LA92 tap off to Watt Lake 956S
n
7L24 termination at Bonnyville 700S
n
7L/9L146 line from Bonnyville 700S to Bourque 970S
n
Kitscoty 705S and lines 7L14/7L130 lines in/out
n
7L53/7L117 line clearance mitigation
n
Bonnyville 700S transformer addition
n
Kitscoty 6L06 decommission
n
Rebuild 80L from South Red Deer 194S to North Red Deer 217S
n
New Wolf Creek 240/138kV Substation 247S
n
New Hazelwood 240/138kV Substation 287S
n
Rebuild 755L Piper Creek 247S to Joffre 535S
n
Rebuild 427L Red Deer 63S to Piper Creek 247S
n
Rebuild 717L from Red Deer 63S to Sylvan Lake 580S
n
New Johnson 240/138 kV Substation 281S
n
Rebuild 717L from Sylvan Lake 580S to Benalto 17S
n
New 138kV Line from Lacombe 212S to Ellis 332S
n
Rebuild 80L from South Red Deer 194S to Red Deer 63S
n
St. Paul Area Upgrades – St. Paul 707S and 7L139/7L70 in/out
n
St. Paul Area Upgrades – Whitby Lake 819S 144kV CB addition
n
7L14 Line clearance mitigation
n
Rebuild 166L
n
Salvage 716L from Wetaskiwin 40S to Ponoka 331S
n
Salvage 80L from Red Deer 63S to Innisfail 214S
n
Salvage 80L from Ponoka 331S to West Lacombe 958S
24-Month Reliability Outlook
PAGE 23
South Region
The South Region of Alberta has the Canada-U.S. border to the south and is bordered on
the north by the Abraham Lake, Caroline, Didsbury and Hanna areas, and on the west and
east by B.C. and Saskatchewan respectively. The region includes Calgary, makes up
approximately 30 per cent of the province’s peak load (mainly residential and commercial)
and has 3,100 MW of Alberta’s total installed generation capacity. The generation is a mix
of hydroelectricity, gas and coal-fired generation, and over 850 MW of wind facilities.
The AESO and the transmission facility owner, AltaLink, are developing project schedules
and specifications for the Southern Alberta Transmission Reinforcement (SATR) phases
one and two. The double-circuit 240kV lines from Bowmanton to Whitla are to be in service
in 2014, which will facilitate wind integration in the southeast.
Due to new load growth in the southeast area, the transmission constraints in the 138 kV
system in the southeast area will continue even after the Medicine Hat 138kV transmission
upgrades within the SATR project are completed in 2016, which will move significant load
from the existing system to the 240 kV system at Bowmanton substation.
Although transmission developments in the southwest were commissioned during 2011
and 2012, some wind generation curtailments will continue to occur under normal system
operations until SATR is complete. Once this is done, transmission capacity to support
existing and new wind generation in the southwest and southeast will be enhanced.
The overload RASs on the southwest system will continue and new RASs may be required
as new wind generation comes online before the completion of SATR. These RASs have
been installed to ensure the area transmission system meets the performance requirements
of Category A, B and C contingencies.
The current 138 and 240 kV systems serving south Calgary and High River, and between
Calgary and the south of the province, are approaching capacity and will require substantial
reinforcement to accommodate load growth, new gas generation connection requests
and south-to-north transfers related to new wind generation.
The AUC has approved the ENMAX Shepard Energy Center connection-related
transmission developments NID for the south-of-Calgary system and the Foothills Area
Transmission Development (FATD East) plan, which was filed the with the AUC on July 5,
2012. These transmission developments will improve transfer capacity between Calgary
and southern Alberta, meet area load growth south of Calgary, and facilitate the connection
of ENMAX’s Shepard gas generation to the AIES. Project components are in service
with completion expected in 2015.
PAGE 24
24-Month Reliability Outlook
The transmission system in the City of Calgary is reaching its limit due to increased load
growth, and it is becoming increasingly difficult to arrange maintenance on many transmission
facilities. When specific transmission equipment is removed from service for maintenance,
the next single contingency can result in uncontrolled loss of load in the area. FATD
completion will address these constraints in south Calgary.
Based on the AESO 2013 Long-term Transmission Plan (filed on Jan. 31, 2014), the AESO
has identified the need for transmission system enhancements to address load growth
and constraints in this region and is planning to file NIDs for transmission additions in
the near future.
Transmission facilities commissioned or expected to be commissioned in the South Region
during 2014 and 2015 include:
n
A new 240 kV 985L between ENMAX SS-25 and Janet 74S
n
Move termination of 936L and 937L 240 kV lines from Janet 74S to East Calgary 5S
n
New 240 kV double-circuit 1064L/1065L from Langdon 102S to Janet 74S
n
New Foothills 237S 240/138 kV substation with two transformers
n
New 240 kV double circuit 1106L/1107L from Foothills 237S to ENMAX SS-65
n
New 240 kV line from ENMAX SS-65 to ENMAX SS-25
n
New 138 kV 434L 138 kV line from Foothills 237S to High River 65S
n
Rebuild 727L 138 kV line for capacity increase
n
A new 138 kV 646L and re-configure 727L/850L
n
Replace existing 911L with new 240 kV double-circuit from Windy Flat 138S
to Foothills 237S
n
A new 240 kV switching station at Windy Flats 138S and termination of 240 kV lines
at the new substation
n
45 MVAr reactor at Bowmanton 244S
n
New 240 kV double circuit 1034L/1035L lines between Cassils 324S and
Bowmanton 244S
n
New 240 kV double circuit 964L/983L lines between Bowmanton 244S and
Whitla 251S
24-Month Reliability Outlook
PAGE 25
North-South Transmission
The Edmonton to Calgary bulk transmission system is comprised of six 240 kV lines
between the Wabamun Lake/Edmonton area and Calgary. These six circuits are collectively
referred to as the South of Keephills-Ellerslie-Genesee (SOK) cutplane. These lines transfer
baseload coal generation and Brazeau hydro generation to the southern part of the province
to meet the major load requirements of the Calgary Region. In 2015, two new HVDC
transmission lines are planned to be in operation.
The Eastern Alberta Transmission Line (EATL) is owned by transmission facility owner (TFO)
ATCO Electric and will connect the Heathfield 2029S converter station, in the vicinity of the
Heartland 12S substation northeast of Edmonton, to the Newell 2075S converter station,
in the vicinity of the West Brooks 28S substation, west of Brooks. The Western Alberta
Transmission Line (WATL) is owned by TFO AltaLink and will connect the Sunnybrook 510S
converter station in the vicinity of Genesee Plant, southwest of Edmonton, to the Crossings
511S converter station in the vicinity of Langdon 102S east of Calgary.
Unlike alternating current (AC) transmission lines, the amount and direction of power flowing
on HVDC transmission lines can be directly controlled either through operator-initiated
action or through automatic control devices in response to system conditions. Consistent
with the AESO’s operation of the AIES, the EATL and WATL lines will be operated in
accordance with reliability criteria.
PAGE 26
24-Month Reliability Outlook
The AESO will operate these lines in accordance with the following principles:
1. Maintain reliability: The AESO needs to operate the HVDC lines to meet reliability
criteria. Accordingly, the HVDC lines will be used to resolve criteria violations under
certain system conditions (i.e., contingencies such as one or more transmission
elements out of service).
2. Reduce transmission constraints: The AESO is mandated to enable
transmission of all in-merit energy and therefore the AESO will operate the HVDC
lines to reduce transmission constraints as a priority over loss management
or system efficiencies while still maintaining adherence to reliability criteria.
Reducing transmission constraints provides improved access to the market.
3. Maximize efficiency: The AESO is mandated to maximize the efficiency of the
AIES. The AESO will schedule the HVDC lines to distribute power flows across
major transmission lines as efficiently as possible while satisfying the reliability
criteria and minimizing transmission constraints. This will result in reduced losses
and overall system efficiency improvements.
To prepare for integration of the two HVDC transmission lines, various engineering studies
are required.
The AESO has been conducting numerous studies including those related to:
n
Establishing the appropriate operating procedures for operation of the HVDC lines
n
Identifying HVDC power flow levels to minimize system losses
n
Analyzing power flows to determine adjustments to various cutplane limits
n
Establishing, in coordination with the TFOs, the operating conditions required to
commission the HVDC lines
This study work will ensure that the HVDC lines are reliably integrated and optimized to
enable the safe, reliable and efficient operation of the AIES.
24-Month Reliability Outlook
PAGE 27
Alberta Intertie Capability
One 500 kV circuit and two 138 kV circuits between Alberta and B.C. comprise three circuits
the Western Electricity Coordinating Council (WECC) defines as Path 1. The current path
rating of the B.C. intertie is 1,000 MW in export17 mode and 1,200 MW in import18 mode.
However, the actual operating limit is lower, primarily due to the need to stay within
equipment limits in the event of generator contingencies within Alberta. The current
maximum transfer capability available for scheduling between Alberta and B.C. is 735 MW
for exports and 780 MW for imports.
The Montana–Alberta Tie Line (MATL), a 230 kV merchant intertie between Montana and
Alberta, was energized in September 2013 and is now in service. This intertie is expected to
provide an alternate source of energy exchange between Alberta and the Northwest U.S. in
the current configuration. MATL has a maximum scheduling transfer capability of 295 MW
for imports and 300 MW for exports.
The B.C. intertie and MATL are subject to a common scheduling limitation arising from the
fact that MATL is under a RAS scheme which results in MATL tripping whenever the B.C.
intertie also trips. This means that the two interties combined are a single contingency.
The primary factor expected to limit import flows on the combined B.C. intertie/MATL is
the requirement to maintain acceptable levels of frequency in Alberta in the event of intertie
separation with the WECC while Alberta is importing. To increase the scheduling capability
across the combined limit while mitigating the frequency risk, the AESO employs Load Shed
Service for imports (LSSi). Depending on Alberta load levels and the availability of LSSi
load for arming, combined imports across the B.C. intertie and MATL can be scheduled
up to a maximum of 765 MW. Further information regarding LSSi is provided in the demand
response section below. Exports can be scheduled to a maximum of 735 MW.
The McNeill back-to-back alternating current AC-to-DC converter station that connects
Alberta and Saskatchewan is referred to as WECC Path 2. A maximum import and export
Total Transfer Capability (TTC) of 153 MW is available. Constraints on either the Alberta or
Saskatchewan system may lower the TTC during real-time operation. The Saskatchewan
intertie is not subject to the combined import constraints which apply to combined B.C./
MATL flows.
Alberta to B.C.
17
B.C. to Alberta.
18
PAGE 28
24-Month Reliability Outlook
Wind Integration
Wind power in Alberta has seen substantial growth in the last few years. As of September
2014, 1,434 MW of generating capacity from 18 wind farms—nine per cent of total installed
generation capacity—was connected to the transmission system. Wind power provided
5.1 per cent of the total energy consumed in Alberta during 2013. There continues to be
strong interest in building wind generation with over 2,400 MW of wind generation projects
in the project list.
The AESO is committed to integrating wind generation while at the same time maintaining
a fair, efficient and openly competitive market for the exchange of electricity and without
compromising system reliability. The AESO released a discussion paper in December
2010, outlining possible products and market rules intended to support wind capacity in
Alberta of 1,500 MW and beyond. Extensive consultation with industry in 2011 culminated
with a recommendation paper from the AESO in December 2012. The Phase Two
Recommendations are:
n
Investigate options for allowing wind to participate in the energy market merit order
n
Explore the need for and development of a new system ramping service, including
the possibilities of:
– Changes to the regulating reserve technical standards
– Options for altering the payment structure of the regulating reserve
The AESO continues to pursue the Phase Two Recommendations with an immediate focus
in 2014 on introducing a mechanism to allow wind to participate in the energy market merit
order. The AESO also continues to conduct analysis exploring the potential need for a
ramping service.
The AESO will continue to work in consultation with industry stakeholders to develop and
implement best practices in wind integration within the Alberta electricity framework.
24-Month Reliability Outlook
PAGE 29
Demand Response
Demand-side participation is a key component of a fair, efficient and openly competitive market.
The first direct way for load customers to participate in the energy market is through
responding to the electricity price in the real-time spot market. Load participates in the
market by voluntarily reducing demand when pool prices exceed their self-defined price
threshold. The AESO publishes a number of reports to help customers manage their
consumption during high-priced hours.
Load also has the opportunity to participate in the supplemental reserve market by reducing
demand when directed by the AESO following a significant loss of generation in Alberta.
Load market participants provided approximately 10 per cent of Supplemental Reserve in
the past two years.
With the implementation of the new contingency reserve standard BAL-002-WECC-AB-2,
the AESO is working on enabling load for the provision of Operating Reserves–Spinning.
In 2013, 479 MW of load was under contract to provide Load Shed Service for imports
(LSSi). LSSi contracts were put in place to support the import capability of the Alberta
transmission system. The AESO has recently increased the transfer capabilities of the
interties made available through the use of LSSi. The AESO has conducted a review of
LSSi and will be pursuing various recommendations to modify LSSi in 2014. As well, the
AESO will conduct a competitive process to replace the LSSi contracts which will expire
at the end of 2014.
PAGE 30
24-Month Reliability Outlook
Highlights of the
24-Month Reliability Outlook
The Alberta Interconnected Electric System (AIES) will continue to provide an adequate level
of reliability using the AESO’s rules, operating practices and procedures. Some congestion
on the system is expected to continue due to load growth and new customer connections in
several regions. The AESO will continue efforts to coordinate outages and develop operating
strategies to minimize constraints until transmission is developed in these areas. The AESO
also plans to minimize some constraints through operational strategies with the HVDC lines
that are planned to come into service in 2015. The AESO’s priority is timely approval and
implementation of proposed transmission upgrades to meet future reliability needs.
Supply reserve margins will be adequate during the next two years. Close coordination of
generator and transmission outages is required to ensure adequate supply and to avoid
constraint events during real-time operation.
24-Month Reliability Outlook
PAGE 31
In Summary
Information in the 24-Month Reliability Outlook 2014–2015 is provided from the perspective
of assessing the AESO’s ability to reliably operate the AIES until the end of 2015.
Supporting information and forecasts referred to throughout this document are available
at www.aeso.ca
This document complements the AESO’s existing publications and supports our
commitment to sharing information with market participants, stakeholders and all
Albertans in an open and transparent manner. Readers are invited to provide comments
or suggestions for future reports.
For more information or to give us your feedback, email [email protected]
PAGE 32
24-Month Reliability Outlook
Blank
(Inside Back Cover)
Alberta Electric System Operator
2500, 330-5th Avenue SW
Calgary, Alberta T2P 0L4
Phone: 403-539-2450
Fax: 403-539-2949
www.aeso.ca
www.poweringalberta.com
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